U.S. patent number 7,198,104 [Application Number 10/852,461] was granted by the patent office on 2007-04-03 for subterranean fluids and methods of cementing in subterranean formations.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Lance E. Brothers, James E. Griffith.
United States Patent |
7,198,104 |
Griffith , et al. |
April 3, 2007 |
Subterranean fluids and methods of cementing in subterranean
formations
Abstract
Subterranean fluids, and more particularly, subterranean fluids
comprising a hydraulic cement in an invert emulsion, and methods of
using such fluids in subterranean operations, are provided. An
example of these methods is a method of cementing a well bore.
Another example of these methods is a method of reducing the cost
to cement a well bore in a subterranean formation.
Inventors: |
Griffith; James E. (Loco,
TX), Brothers; Lance E. (Chickasha, OK) |
Assignee: |
Halliburton Energy Services,
Inc. (Duncan, OK)
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Family
ID: |
35448127 |
Appl.
No.: |
10/852,461 |
Filed: |
May 24, 2004 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20050034867 A1 |
Feb 17, 2005 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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10639702 |
Aug 12, 2003 |
7147056 |
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Current U.S.
Class: |
166/294 |
Current CPC
Class: |
C04B
28/02 (20130101); C09K 8/502 (20130101); C09K
8/467 (20130101); C09K 8/32 (20130101); C09K
8/40 (20130101); C04B 28/04 (20130101); C09K
8/424 (20130101); C04B 28/021 (20130101); C04B
28/18 (20130101); C04B 28/02 (20130101); C04B
14/10 (20130101); C04B 14/108 (20130101); C04B
18/08 (20130101); C04B 18/146 (20130101); C04B
20/002 (20130101); C04B 22/064 (20130101); C04B
24/08 (20130101); C04B 24/121 (20130101); C04B
2103/22 (20130101); C04B 2103/50 (20130101); C04B
28/02 (20130101); C04B 24/08 (20130101); C04B
2103/22 (20130101); C04B 2103/40 (20130101); C04B
2103/44 (20130101); C04B 2103/46 (20130101); C04B
28/04 (20130101); C04B 14/10 (20130101); C04B
18/146 (20130101); C04B 20/002 (20130101); C04B
24/121 (20130101); C04B 2103/22 (20130101); C04B
2103/46 (20130101); C04B 2103/50 (20130101); C04B
28/021 (20130101); C04B 14/104 (20130101); C04B
18/146 (20130101); C04B 20/002 (20130101); C04B
22/064 (20130101); C04B 24/121 (20130101); C04B
2103/22 (20130101); C04B 2103/46 (20130101); C04B
2103/50 (20130101); C04B 28/18 (20130101); C04B
14/10 (20130101); C04B 14/108 (20130101); C04B
18/146 (20130101); C04B 20/002 (20130101); C04B
24/121 (20130101); C04B 2103/22 (20130101); C04B
2103/46 (20130101); C04B 2103/50 (20130101); C04B
28/04 (20130101); C04B 14/10 (20130101); C04B
18/08 (20130101); C04B 18/146 (20130101); C04B
22/064 (20130101); C04B 24/121 (20130101); C04B
24/2611 (20130101); C04B 2103/22 (20130101); C04B
2103/46 (20130101); C04B 2103/50 (20130101); C04B
28/04 (20130101); C04B 14/10 (20130101); C04B
14/108 (20130101); C04B 18/08 (20130101); C04B
18/146 (20130101); C04B 22/064 (20130101); C04B
24/2611 (20130101); C04B 2103/22 (20130101); C04B
2103/40 (20130101); C04B 2103/46 (20130101); C04B
2103/50 (20130101); C04B 2111/00146 (20130101); Y02W
30/91 (20150501); Y02W 30/94 (20150501); Y02W
30/92 (20150501) |
Current International
Class: |
E21B
33/14 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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1 138 740 |
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Oct 2001 |
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EP |
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2 329 657 |
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Mar 1999 |
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GB |
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2 342 671 |
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Apr 2000 |
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GB |
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Other References
Foreign communication from a related counterpart application dated
Dec. 27, 2005. cited by other .
Halliburton brochure entitled "HR.RTM.-5 Cement Additive" dated
1998. cited by other .
Halliburton brochure entitled "HR.RTM.-15 Cement Retarder" dated
1999. cited by other .
Paper entitled "Deepwater Cementing Challenges--An Overview of
Offshore Brazil, Gulf of Mexico, and West Africa," by George Fuller
et al. cited by other .
Paper entitled "Practices for Providing Zonal Isolation in
Conjunction With Expandable Casing Jobs-Case Histories," by Tom
Sanders et al., dated 2003. cited by other .
SPE 77751 paper entitled "Use of Settable Spotting Fluid Improves
Expandable Casing Process-Case History," by Oladele O. Owoeye et
al., dated 2002. cited by other.
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Primary Examiner: Bates; Zakiya W.
Attorney, Agent or Firm: Roddy; Craig W. Baker Botts,
L.L.P.
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATION
This application is a continuation-in-part of U.S. application Ser.
No. 10/639,702 entitled "Subterranean Fluids and Methods of Using
These Fluids in Subterranean Formations," filed on Aug. 12, 2003,
now U.S. Pat. No. 7,147,056 incorporated by reference herein for
all purposes, and from which priority is claimed pursuant to 35
U.S.C. .sctn. 120.
Claims
What is claimed is:
1. A method of cementing a well bore, comprising: introducing a
well fluid comprising hydraulic cement, an oil viscosifier, and an
invert emulsion into a well bore containing an oil-based drilling
fluid so as to displace at least a portion of the oil-based
drilling fluid from the well bore; disposing a pipe string in the
well bore so as to create an annulus between the pipe string and
the well bore such that a portion of the well fluid resides in the
annulus and a portion of the well fluid resides in the pipe string;
flowing a cement composition through the pipe string and into the
annulus so as to displace the portion of the well fluid out of the
pipe string and into the annulus; and allowing both the well fluid
and cement composition to develop compressive strength along a
desired length of the well bore.
2. The method of claim 1, wherein the invert emulsion comprises
oil, water, and a surfactant.
3. The method of claim 2, wherein the surfactant is an emulsifying
surfactant.
4. The method of claim 3, wherein the emulsifying surfactant
comprises a Tallow di-amine substituted with 3 moles of ethylene
oxide.
5. The method of claim 4, wherein the emulsifying surfactant
comprises about 60% active ingredient.
6. The method of claim 3, wherein the emulsifying surfactant is
present in the well fluids of the present invention in an amount in
the range of from about 5% to about 15% by weight of the oil.
7. The method of claim 2, wherein the oil comprises a long-chain
hydrocarbon.
8. The method of claim 2, wherein the oil is present in the well
fluids of the present invention in an amount in the range of from
about 40% to about 70% by volume of the invert emulsion.
9. The method of claim 2, wherein the water is present in an amount
in the range of from about 30% to about 60% by volume of the invert
emulsion.
10. The method of claim 1, wherein the well fluid and cement
composition provide zonal isolation along the length of the well
bore.
11. The method of claim 10, wherein the well fluid and cement
composition form a cement sheath along the length of the well
bore.
12. The method of claim 11, wherein the cement sheath has a volume,
and wherein the well fluid comprises between about 0.01% and about
75% of the volume of the cement sheath.
13. The method of claim 1, wherein the invert emulsion is present
in the well fluid in an amount in the range of from about 20% to
about 60% by weight.
14. The method of claim 1, wherein the well fluid has a density in
the range of from about 11 to about 17 pounds per gallon.
15. The method of claim 1, wherein the hydraulic cement is present
in the well fluids of the present invention in an amount in the
range of from about 25% to about 60% by weight of the well
fluid.
16. The method of claim 1, wherein the hydraulic cement comprises a
Portland cement.
17. The method of claim 1, wherein the hydraulic cement comprises
ASTM Class C fly ash, a mixture of ASTM Class F fly ash and
hydrated lime, a mixture of vitrified shale and hydrated lime, or
mixtures thereof.
18. The method of claim 1, wherein the hydraulic cement is present
in an amount in the range of from about 50% to about 70% by weight
of the fluid.
19. The method of claim 1, wherein the oil viscosifier is an
organophilic clay.
20. The method of claim 1, wherein the oil viscosifier is present
in an amount sufficient to provide a fluid having a desired
viscosity.
21. The method of claim 1, wherein the oil viscosifier is present
in an amount in the range of from about 0.01% to about 2% by weight
of the invert emulsion.
22. The method of claim 1, wherein the well fluid further comprises
a set retarder.
23. The method of claim 22, wherein the set retarder is present in
an amount less than about 4% by weight of the hydraulic cement.
24. The method of claim 22, wherein the set retarder is present in
an amount less than about 1% by weight of the hydraulic cement.
25. The method of claim 1, wherein the well fluid further comprises
a fluid loss control additive, a salt, fumed silica, a weighting
agent, microspheres, a defoaming agent, or a mixture thereof.
26. The method of claim 1, wherein the well fluid has a density in
the range of from about 11 to about 17 pounds per gallon; wherein
the invert emulsion comprises oil, water, and a surfactant; wherein
the surfactant comprises an emulsifying surfactant comprising a
Tallow di-amine substituted with 3 moles of ethylene oxide; wherein
the surfactant is present in the well fluid in an amount in the
range of about 5% to about 15% by weight of the oil; wherein the
invert emulsion is present in the well fluid in an amount in the
range of from about 20% to about 60% by weight; wherein the oil
comprises a long-chain hydrocarbon and is present in the well fluid
in an amount in the range of from about 40% to about 70% by volume
of the invert emulsion; and wherein the water is present in an
amount in the range of from about 30% to about 60% by volume of the
invert emulsion.
27. A method of cementing a well bore in a subterranean formation,
comprising: using a cement composition to form a portion of a
cement sheath along the well bore; and using a well fluid to form a
portion of the cement sheath along the well bore, wherein the well
fluid comprises a hydraulic cement, an oil viscosifier, and an
invert emulsion.
28. The method of claim 27 wherein the invert emulsion comprises
oil, water, and a surfactant.
29. The method of claim 28, wherein the surfactant is an
emulsifying surfactant.
30. The method of claim 29, wherein the emulsifying surfactant
comprises a Tallow di-amine substituted with 3 moles of ethylene
oxide.
31. The method of claim 29 wherein the emulsifying surfactant
comprises about 60% active ingredient.
32. The method of claim 29, wherein the emulsifying surfactant is
present in the well fluids of the present invention in an amount in
the range of from about 5% to about 15% by weight of the oil.
33. The method of claim 28, wherein the oil comprises a long-chain
hydrocarbon.
34. The method of claim 28, wherein the oil is present in the well
fluids of the present invention in an amount in the range of from
about 40% to about 70% by volume of the invert emulsion.
35. The method of claim 28, wherein the water is present in an
amount in the range of from about 30% to about 60% by volume of the
invert emulsion.
36. The method of claim 27, wherein the cement sheath provides
zonal isolation along the length of the well bore.
37. The method of claim 27, wherein the cement sheath has a volume,
and wherein the well fluid comprises between about 0.01% and about
75% of the volume of the cement sheath.
38. The method of claim 27, wherein the invert emulsion is present
in the well fluid in an amount in the range of from about 20% to
about 60% by weight.
39. The method of claim 27, wherein the well fluid has a density in
the range of from about 11 to about 17 pounds per gallon.
40. The method of claim 27, wherein the hydraulic cement is present
in the well fluids of the present invention in an amount in the
range of from about 25% to about 60% by weight of the well
fluid.
41. The method of claim 27, wherein the hydraulic cement comprises
a Portland cement.
42. The method of claim 27, wherein the hydraulic cement comprises
ASTM Class C fly ash, a mixture of ASTM Class F fly ash and
hydrated lime, a mixture of vitrified shale and hydrated lime, or
mixtures thereof.
43. The method of claim 27, wherein the hydraulic cement is present
in an amount in the range of from about 50% to about 70% by weight
of the fluid.
44. The method of claim 27, wherein the oil viscosifier is an
organophilic clay.
45. The method of claim 27, wherein the oil viscosifier is present
in an amount sufficient to provide a fluid having a desired
viscosity.
46. The method of claim 27, wherein the oil viscosifier is present
in an amount in the range of from about 0.01% to about 2% by weight
of the invert emulsion.
47. The method of claim 27, wherein the well fluid further
comprises a set retarder.
48. The method of claim 47, wherein the set retarder is present in
an amount less than about 4% by weight of the hydraulic cement.
49. The method of claim 47, wherein the set retarder is present in
an amount less than about 1% by weight of the hydraulic cement.
50. The method of claim 27, wherein the well fluid further
comprises a fluid loss control additive, a salt, fumed silica, a
weighting agent, microspheres, a defoaming agent, or a mixture
thereof.
51. The method of claim 27, wherein the well fluid has a density in
the range of from about 11 to about 17 pounds per gallon; wherein
the invert emulsion comprises oil, water, and a surfactant; wherein
the surfactant comprises an emulsifying surfactant comprising a
Tallow di-amine substituted with 3 moles of ethylene oxide; wherein
the surfactant is present in the well fluid in an amount in the
range of about 5% to about 15% by weight of the oil; wherein the
invert emulsion is present in the well fluid in an amount in the
range of from about 20% to about 60% by weight; wherein the oil
comprises a long-chain hydrocarbon and is present in the well fluid
in an amount in the range of from about 40% to about 70% by volume
of the invert emulsion; and wherein the water is present in an
amount in the range of from about 30% to about 60% by volume of the
invert emulsion.
Description
BACKGROUND OF THE INVENTION
The present invention relates to subterranean fluids, and more
particularly, to subterranean fluids comprising a hydraulic cement
and an invert emulsion, and methods of using such fluids in
subterranean operations.
During the drilling of a well bore in a subterranean formation, a
drilling fluid may be circulated through a drill pipe and drill bit
into the well bore, and subsequently flow upward through the well
bore to the surface. The drilling fluid, inter alia, cools the
drill bit, lubricates the rotating drill pipe to prevent it from
sticking to the walls of the well bore, prevents blowouts by
providing hydrostatic pressure to counteract the sudden entrance
into the well bore of high pressure formation fluids, and removes
drilled cuttings from the well bore. Typically, after a well bore
is drilled to a desired final depth, the drill pipe and drill bit
are withdrawn from the well bore and the drilling fluid is left
therein so as to, inter alia, provide hydrostatic pressure on
permeable formations penetrated by the well bore, thereby
preventing the flow of formation fluids into the well bore.
A common subsequent step in completing the well bore usually
involves placing a pipe string (e.g., casing), into the well bore.
Depending upon factors such as, inter alia, the depth of the well
bore and any difficulties in placing the pipe string therein, the
drilling fluid may remain relatively static in the well bore for an
extended period of time (e.g., up to about 2 weeks). While drilling
fluids generally are not settable (e.g., they do not set into hard
impermeable sealing masses when static), drilling fluids may
increase in gel strength over time. Accordingly, the drilling fluid
progressively may increase in gel strength, during the time in
which it remains static, such that portions of the drilling fluid
in the well bore may become increasingly difficult to displace.
Upon placement of the pipe string in the well bore, primary
cementing typically is performed. This commonly involves cementing
the pipe string disposed in the well bore by pumping a cement
composition through the pipe string and into an annulus between the
pipe string and the walls of the well bore, thereby displacing the
drilling fluid in the annulus. However, if the drilling fluid has
developed sufficient gel strength while in the well bore, an
operator may be unable to displace all of the drilling fluid with
the cement composition. Accordingly, the cement composition may
bypass portions of the drilling fluid in the well bore. This may be
problematic, inter alia, because the drilling fluid generally is
not settable; therefore, formation fluids may enter and flow along
the well bore, which is highly undesirable.
Operators have attempted to solve this problem by developing
settable spotting fluid compositions, inter alia, to displace
drilling fluids from well bores promptly after their use. However,
these methods often have not met with success, as conventional
settable spotting fluids commonly include blast furnace slag and
other hydraulic components that may begin to set at relatively low
temperatures, e.g., temperatures less than about 90.degree. F.
Also, certain slag-containing settable spotting fluids may be
intolerant to cement composition contamination, causing the
settable spotting fluids to set prematurely upon contact with well
cement. Operators often attempt to counteract this tendency to
prematurely set by adding a strong set retarder to the spotting
fluid, and/or by separating the spotting fluid from the cement
composition through the use of a spacer fluid.
Conventional settable spotting fluids also may demonstrate other
problems, including, but not limited to, undesirable instability as
well as a general inability to develop significant compressive
strength upon setting. For example, the invert emulsions found in
many conventional settable spotting fluids typically become
unstable within about one week after their formulation. This is
problematic, inter alia, because it often necessitates formulating
the invert emulsion shortly before placing the settable spotting
fluid in a subterranean formation. If an excessive amount of the
invert emulsion is formed, it generally cannot be re-used and often
is disposed of, which disposal may further increase the cost of a
particular job. Furthermore, the general inability of most
conventional settable spotting fluids to develop significant
compressive strength upon setting also is problematic, because,
inter alia, where formation fluids are present under a pressure
sufficient to overcome the settable spotting fluid's low
compressive strength, such formation fluids may continue to enter
and flow along the well bore, which is undesirable and defeats a
major purpose of using settable spotting fluids, which is to
provide zonal isolation.
SUMMARY OF THE INVENTION
The present invention relates to subterranean fluids, and more
particularly, to subterranean fluids comprising a hydraulic cement
and an invert emulsion, and methods of using such fluids in
subterranean operations.
An example of a method of the present invention is a method of
cementing a well bore, comprising: introducing a well fluid
comprising hydraulic cement, an oil viscosifier, and an invert
emulsion into a well bore containing an oil-based drilling fluid so
as to displace at least a portion of the oil-based drilling fluid
from the well bore; disposing a pipe string in the well bore so as
to create an annulus between the pipe string and the well bore such
that a portion of the well fluid resides in the annulus and a
portion of the well fluid resides in the pipe string; flowing a
cement composition through the pipe string and into the annulus so
as to displace the portion of the well fluid out of the pipe string
and into the annulus; and allowing both the well fluid and cement
composition to develop compressive strength along a desired length
of the well bore.
Another example of a method of the present invention is a method of
reducing the cost to cement a well bore in a subterranean
formation, comprising the step of using a well fluid to form a
portion of a cement sheath along the well bore, wherein the well
fluid comprises a hydraulic cement, an oil viscosifier, and an
invert emulsion.
The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
DESCRIPTION OF EMBODIMENTS
The present invention relates to subterranean fluids, and more
particularly, to subterranean fluids comprising a hydraulic cement
and an invert emulsion, and methods of using such fluids in
subterranean operations.
The subterranean well fluids of the present invention generally
comprise water, an oil, an emulsifying surfactant for emulsifying
the oil with water whereby an invert (e.g., oil-external) emulsion
is formed, a hydraulic cement, and an oil viscosifier. Other
additives suitable for use in subterranean formations also may be
added to these well fluids if desired. Generally, the invert
emulsion is present in the well fluids of the present invention in
an amount in the range of from about 20% to about 60% by weight. In
certain embodiments, the invert emulsion is present in the well
fluids of the present invention in an amount in the range of from
about 30% to about 55% by weight. Generally, the subterranean well
fluids of the present invention have a density in the range of from
about 11 to about 17 pounds per gallon.
Any oil may be used with the subterranean well fluids of the
present invention. In certain embodiments, the oil comprises one or
more long-chain hydrocarbons. A particularly suitable mixture of
long-chain hydrocarbons is commercially available under the trade
designation "ESCAID 110.TM." from the ExxonMobil Corporation.
Generally, the oil is present in the well fluids of the present
invention in an amount in the range of from about 40% to about 70%
by volume of the invert emulsion. In certain embodiments, the oil
is present in the well fluids of the present invention in an amount
in the range of from about 45% to about 55% by volume of the invert
emulsion.
The water used in the subterranean well fluids of the present
invention may be fresh water, saltwater (e.g., water containing one
or more salts dissolved therein), brine (e.g., saturated
saltwater), or seawater. Generally, the water may be from any
source provided that it does not contain an excess of compounds
(e.g., dissolved inorganics, such as tannin), that may adversely
affect other components in the cement composition. The water may be
present in the well fluids of the present invention in an amount
sufficient to form a pumpable slurry. More particularly, the water
is present in the well fluids of the present invention in an amount
in the range of from about 30% to about 60% by volume of the invert
emulsion. In certain embodiments, the water is present in the well
fluids of the present invention in an amount in the range of from
about 45% to about 55% by volume of the invert emulsion.
A wide variety of emulsifying surfactants may be used in the well
fluids of the present invention to emulsify the oil with water. An
example of a particularly suitable emulsifying surfactant is a
Tallow di-amine substituted with 3 moles of ethylene oxide that is
available from Special Products, Inc., in Houston, Tex. Such
emulsifying surfactant comprises about 60% active ingredient.
Generally, the emulsifying surfactant may be present in the invert
emulsion in an amount in the range of from about 5% to about 15% by
weight of the oil. In certain embodiments, the emulsifying
surfactant may be present in the invert emulsion in an amount in
the range of from about 7.5% to about 12% by weight of the oil.
Any hydraulic cement suitable for use in subterranean applications
may be used in the present invention. In certain embodiments, the
hydraulic cement is a Portland cement. Generally, the hydraulic
cement is present in the well fluids of the present invention in an
amount in the range of from about 25% to about 60% by weight. In
certain embodiments, the hydraulic cement is present in the well
fluids of the present invention in an amount in the range of from
about 50% to about 60% by weight.
Alternatively, the hydraulic cement may comprise fly ash. As
referred to herein, the term "fly ash" refers to the finely divided
residue that results from the combustion of ground or powdered coal
and is carried by the flue gases generated therefrom. ASTM Class C
or equivalent fly ash contains both silica and calcium, and when
mixed with water forms a cementitious mixture that sets into a hard
impermeable mass, e.g., calcium silicate hydrate. In certain other
embodiments, the hydraulic cement may comprise a source of calcium
ion along with vitrified shale or Class F or equivalent fly ash.
ASTM Class F fly ash does not contain a reactive form of calcium,
and an external source of calcium ion generally is required for it
to form a cementitious composition with water. Generally, hydrated
lime may be mixed with Class F or the equivalent fly ash in an
amount in the range of from about 5% to about 50% by weight of the
fly ash. As referred to herein, the term "hydrated lime" will be
understood to mean calcium hydroxide (Ca(OH).sub.2). Where the
hydraulic cement comprises vitrified shale or fly ash, the
hydraulic cement generally is present in the well fluids of the
present invention in an amount in the range of from about 50% to
about 70% by weight; in certain embodiments, the hydraulic cement
may be present in an amount in the range of from about 55% to about
65% by weight. Where the hydraulic cement comprises fly ash,
certain embodiments of the well fluids of the present invention may
use ASTM Class F fly ash together with hydrated lime. Where the
hydraulic cement comprises vitrified shale, a source of calcium ion
(e.g., hydrated lime) generally is required for it to form a
cementitious composition with water. An example of a suitable
vitrified shale is commercially available under the trade name
"PRESSUR-SEAL.RTM. FINE LCM" from TXI Energy Services, Inc., in
Houston, Tex. An example of a suitable hydrated lime is
commercially available from Continental Lime, Inc., of Salt Lake
City, Utah.
The well fluids of the present invention comprise an oil
viscosifier. Any known viscosifier that is compatible with an oil
may be suitable for use in the well fluids of the present
invention. An example of a suitable oil viscosifier is an
organophilic clay commercially available under the trade name
"CLAYTONE II" from Southern Clay Products, Inc., of Princeton, N.J.
Where present, the oil viscosifier may be included in the well
fluids of the present invention in an amount sufficient to provide
a well fluid having a desired viscosity. More particularly, the oil
viscosifier may be present in the well fluids of the present
invention in an amount in the range of from about 0.01% to about 2%
by weight of the invert emulsion. In certain embodiments, the oil
viscosifier may be present in the well fluids of the present
invention in an amount in the range of from about 0.25% to about
0.6% by weight of the invert emulsion.
Optionally, the well fluids of the present invention further may
comprise a set retarder. Examples of suitable set retarders include
those that are commercially available from Halliburton Energy
Services, Inc., of Duncan, Okla., under the trade names
"HR.RTM.-5," and "HR.RTM.-15." When used in well fluids of the
present invention, the amount of set retarder present typically
ranges from about 0.01% to about 4% by weight of the hydraulic
cement, although other concentrations are possible within the
teachings of the present invention. In certain embodiments, the set
retarder may be present in the well fluids of the present invention
in an amount in the range from about 0.01% to about 1% by weight of
the hydraulic cement. Furthermore, the exact amount of set retarder
chosen for a particular application may vary, depending on a
variety of factors including, but not limited to, the temperature
of the well into which the well fluid is to be introduced.
Optionally, the well fluids of the present invention further may
comprise other additives as deemed appropriate by one skilled in
the art with the benefit of this disclosure. Examples of such
additives include, inter alia, fluid loss control additives, salts,
fumed silica, weighting agents, microspheres, defoaming agents, and
the like.
The well fluids of the present invention may be prepared in a
variety of ways. Generally, the well fluids may be prepared by
dispersing the surfactant into the oil at low shear. The
organophilic clay generally is added to the oil at this time (e.g.,
after the surfactant). Water then may be added at a slightly higher
shear. The resulting mixture then may be subjected to high shear,
inter alia, to form an emulsion. Afterwards, any dry blended
materials (e.g., the hydraulic cement) may be added.
Among other benefits, the well fluids of the present invention do
not significantly increase in gel strength over time, and generally
are displaced easily after being static in the well bore for a long
period of time, e.g., a time period of about one week or more.
Among other benefits, if the well fluids of the present invention
are permitted to remain in an annulus in a well bore, they
ultimately will set into a solid mass, thereby facilitating zonal
isolation. Among other benefits, the oil-external emulsion formed
within the well fluids of the present invention may be stable for a
period of time up to about 3 weeks, thereby, inter alia, permitting
the invert emulsion to be prepared as a separate component of the
well fluid and sent to a job site far in advance of its use. The
stability of the oil-external emulsion formed within the well
fluids of the present invention, inter alia, may permit any unused
portion of the invert emulsion to be returned, and re-used in a
subsequent operation, without necessitating disposal.
In certain embodiments, the well fluids of the present invention
may be used to at least partially displace an oil-based drilling
fluid resident within a well bore drilled to total depth where the
oil-based drilling fluid has not yet gained significant gel
strength. The oil-based drilling fluid may have been unable to gain
static gel strength due to, inter alia, its constant circulation
through equipment such as the drill pipe, drill bit, and pumps.
Generally, the well fluids of the present invention may displace
the oil-based drilling fluid to a level above those portions of the
well bore that contain fractures and other permeable areas or
zones. After the well bore has been filled at least partially with
a well fluid of the present invention, the pipe string to be
cemented may be placed into the well bore. Some amount of oil-based
drilling fluid may be present within the pipe string during this
time. When the well cement composition is pumped through the pipe
string into the annulus, it may readily displace the fluids within
the pipe string and annulus. Any amount of the well fluids of the
present invention that may remain in fractures or other permeable
areas or zones in the well bore after the annulus has been filled
with the well cement composition ultimately will set therein, due
to, inter alia, the ability of the well fluids to develop
compressive strength upon setting, thereby preventing the
undesirable entry into, or flow of formation fluids within, the
annulus. In certain embodiments where the casing is subjected to an
internal pressure test after the well cement composition has
set--which pressure test potentially could crack a portion of the
set well cement composition--the presence (post-cementing) of a
portion of the well fluids of the present invention in fractures or
other permeable areas within the well bore may permit such portion
of the well fluids of the present invention to flow into the cracks
within the cement and set therein, thereby enhancing the integrity
of the set well cement composition.
In another embodiment, the well fluids of the present invention may
be used to form at least a portion of a cement sheath of a well
bore (e.g., the well fluids of the present invention may be used as
a "lead" or "filler" cement), thereby reducing the amount of
conventional cement composition required to cement a given length
of well bore. For example, an operator may use an oil-based
drilling fluid to drill a well bore to a desired depth. A well
fluid of the present invention then may be used to at least
partially displace the oil-based drilling fluid that is resident
within the well bore, at a time when the oil-based drilling fluid
has not yet gained significant gel strength. This may be
accomplished, inter alia, by pumping the well fluid of the present
invention through the drill pipe and into the annulus between the
drill pipe and the walls of the well bore. After the well bore has
been filled at least partially with a well fluid of the present
invention, the drill pipe may be removed from the well bore. At
this point, the differing densities of the oil-based drilling fluid
that remains in the well bore and the well fluid of the present
invention may cause the oil-based drilling fluid to stratify atop
the well fluid of the present invention, forming an interface
between the two fluids. Next, the casing to be cemented may be
placed into the well bore to a desired degree. In certain
embodiments, the casing may be inserted at or about the interface
between the oil-based drilling fluid and the well fluid of the
present invention. An additional portion of a well fluid of the
present invention then may be placed in the well bore (e.g., by
pumping the additional portion of the well fluid through the
casing), so that the remainder of the oil-based drilling fluid is
displaced out of the well bore through the annulus between the
casing and the walls of the well bore. The remainder of the casing
then may be placed within the well bore. A cement composition then
may be pumped through the casing and into the annulus, at least
partially displacing the well fluid of the present invention into
the annulus ahead of the cement composition. In embodiments such as
this, the well fluid of the present invention may be permitted to
remain in place in a portion of the annulus that is uphole (e.g.,
nearer to the well head) of the cement composition. In these
embodiments where the well fluids of the present invention are used
to form at least a portion of the cement sheath, the well fluids
generally will not comprise a set retarder, or will comprise a set
retarder in an amount less than about 1% by weight. Because these
embodiments of the well fluids of the present invention contain
minimal or no set retarder, the well fluid then may begin to set
and build sufficient compressive strength to form at least a "lead"
portion of the cement sheath of the well bore. Below the "lead"
portion of the cement sheath formed using the well fluid of the
present invention, the cement composition placed in the well bore
after the well fluid also may set and form the downhole portion of
the cement sheath. This may allow an operator to use a reduced
amount of cement composition to form the cement sheath, helping to
alleviate total cementing costs. For example, an operator desiring
to cement 5,000 linear feet of well bore may displace an oil-based
drilling fluid with, e.g., 3,000 linear feet of a well fluid of the
present invention, then use 2,000 linear feet of a cement
composition to at least partially displace the well fluid, such
that the lowermost 2,000 linear feet of the cement sheath are at
least partially formed using the well cement composition, while the
uppermost 3,000 linear feet of the cement sheath are at least
partially formed using the well fluid of the present invention. In
certain embodiments, the well fluids of the present invention may
be present in the cement sheath in an amount in the range of from
about 0.01% to about 75% of the volume of the cement sheath.
In yet another embodiment, the well fluids of the present invention
may be used in connection with the installation of expandable
casing. For example, expandable casing may be placed within a well
bore comprising a well fluid of the present invention, after which
the expandable casing may be expanded out, and the well fluid of
the present invention may be permitted to set. Optionally, a
cementing plug may be displaced into the casing, inter alia, so as
to displace the portion of the well fluid resident within the
casing before the well fluid sets. Alternatively, after permitting
the well fluid of the present invention to set, the portion of the
well fluid within the casing may be drilled out. Expandable screens
also may be used in accordance with the well fluids of the present
invention.
While a number of embodiments described herein relate to
subterranean well cementing, it will be understood that other well
treatment fluids, including, but not limited to, spacer fluids, may
also be prepared according to the present invention. As referred to
herein, the term "spacer fluid" will be understood to mean a fluid
placed within a well bore to separate fluids, e.g., to separate a
drilling fluid within the well bore from a cement composition that
subsequently will be placed within the well bore. For example,
after an operator has drilled a well bore to a desired depth using
an oil-based drilling fluid, the operator may remove the drill pipe
and insert the casing to be cemented into the well bore. The
operator then may place a desired amount of a well fluid of the
present invention into the well bore. In certain embodiments, the
well fluid may be placed in the well bore in an amount sufficient
to fill the casing and a portion of the annulus between the casing
and the walls of the well bore. The operator then may place a
cement composition into the well bore (e.g., through the
casing).
An example of a method of the present invention is a method of
cementing a well bore, comprising: introducing a well fluid
comprising hydraulic cement, an oil viscosifier, and an invert
emulsion of oil, water, and a surfactant into a well bore
containing an oil-based drilling fluid so as to displace at least a
portion of the oil-based drilling fluid from the well bore;
disposing a pipe string in the well bore so as to create an annulus
between the pipe string and the well bore such that a portion of
the well fluid resides in the annulus and a portion of the well
fluid resides in the pipe string; flowing a cement composition
through the pipe string and into the annulus so as to displace the
portion of the well fluid out of the pipe string and into the
annulus; and allowing both the well fluid and cement composition to
develop compressive strength along a desired length of the well
bore. Generally, the well fluid and cement composition will develop
sufficient compressive strength to form a cement sheath that
provides zonal isolation along the well bore.
Another example of a method of the present invention is a method of
reducing the cost to cement a well bore in a subterranean
formation, comprising the step of using a well fluid to form a
portion of a cement sheath along the well bore, wherein the well
fluid comprises a hydraulic cement, an oil viscosifier, and an
invert emulsion. Optionally, additional steps may include, inter
alia, using a cement composition to form a portion of the cement
sheath (e.g., the remainder of the cement sheath).
A preferred example of a fluid composition that may be used with
the present invention comprises: 108 grams of long-chain
hydrocarbons, 10 grams of surfactant comprising a Tallow di-amine
substituted with 3 moles of ethylene oxide, 2.16 grams organophilic
clay, 135 grams of water, and 250 grams Portland cement.
To facilitate a better understanding of the present invention, the
following examples of some embodiments are given. In no way should
such examples be read to limit, or to define, the scope of the
invention.
EXAMPLE 1
Rheological testing was performed on various sample compositions,
in order to compare the compatibility of the well fluids of the
present invention with conventional oil-based drilling fluids. The
testing was performed on a Fann Model 35 viscometer at 140.degree.
F. per API Recommended Practice 10B.
Sample Composition No. 1 comprised an oil-based drilling fluid
containing 11 lb/gal of Accolade drilling fluid.
Sample Composition No. 2 comprised 95% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 1) and 5% by volume of a well fluid of the present invention
having a density of 11.6 lb/gallon and comprising an emulsion that
comprised 108 grams ESCAID 110, 10 grams surfactant, 2.16 grams
organophilic clay, and 135 grams of water mixed with 250 grams of
Portland Cement.
Sample Composition No. 3 comprised 75% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 1) and 25% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 2).
Sample Composition No. 4 comprised 50% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 1) and 50% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 2).
Sample Composition No. 5 comprised 25% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 1) and 75% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 2) by volume.
Sample Composition No. 6 comprised 5% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 1) and 95% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 2).
Sample Composition No. 7 comprised a well fluid of the present
invention (having the same composition as the well fluid described
above in the description of Sample Composition No. 2).
Sample Composition No. 8 comprised an oil-based drilling fluid
containing 12.4 lb/gal of Nova Plus drilling fluid.
Sample Composition No. 9 comprised 95% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 8) and 5% by volume of a well fluid of the present invention
having a density of 13.0 lb/gallon comprising an emulsion that
comprised 108 grams ESCAID 110, 10 grams surfactant, 2.16 grams
organophilic clay, and 135 grams of water mixed with 250 grams of
Portland Cement and 88 grams of Hi-Dense No. 4 as a weighting
agent.
Sample Composition No. 10 comprised 75% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 8) and 25% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 9).
Sample Composition No. 11 comprised 50% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 8) and 50% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 9).
Sample Composition No. 12 comprised 25% by volume of an oil-based
drilling fluid (having the same composition as Sample Composition
No. 8) and 75% by volume of a well fluid of the present invention
(having the same composition as the well fluid described above in
the description of Sample Composition No. 9).
Sample Composition No. 13 comprised a well fluid of the present
invention (having the same composition as the well fluid of Sample
Composition No. 9).
The results are set forth in Table 1 below.
TABLE-US-00001 TABLE 1 Sample Fluid Yield Point (lb/100 ft.sup.2)
Sample Composition No. 1 10 Sample Composition No. 2 8 Sample
Composition No. 3 5 Sample Composition No. 4 5 Sample Composition
No. 5 5 Sample Composition No. 6 8 Sample Composition No. 7 7
Sample Composition No. 8 7 Sample Composition No. 9 6 Sample
Composition No. 10 4 Sample Composition No. 11 4 Sample Composition
No. 12 5 Sample Composition No. 13 10
Accordingly, the above example demonstrates, inter alia, that the
well fluids of the present invention are compatible with
conventional oil-based drilling fluids, and that the addition of
the well fluids of the present invention to such oil-based drilling
fluids does not cause an appreciable increase in gelation or
viscosity.
Therefore, the present invention is well adapted to carry out the
objects and attain the ends and advantages mentioned as well as
those which are inherent therein. While the invention has been
depicted and described by reference to embodiments of the
invention, such a reference does not imply a limitation on the
invention, and no such limitation is to be inferred. The invention
is capable of considerable modification, alternation, and
equivalents in form and function, as will occur to those ordinarily
skilled in the pertinent arts and having the benefit of this
disclosure. The depicted and described embodiments of the invention
are only, and are not exhaustive of the scope of the invention.
Consequently, the invention is intended to be limited only by the
spirit and scope of the appended claims, giving full cognizance to
equivalents in all respects.
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